Composition for and process of recovering oil from an oil-bearing formation

ABSTRACT

A composition for forming a foam, a foam composition, and a process for using the foam composition to recover oil from an oil-bearing formation are provided. The composition includes water, a surfactant mixed with the water, and fly-ash particles suspended in the mixture of water and surfactant, where the fly-ash particles have a particle size distribution with an average particle size of less than 200 nm, and where the suspension has an absolute zeta potential of from 10 mV to 40 mV. The composition may be mixed with a gas to produce a foam composition, and the foam composition may be contacted with oil in an oil-bearing formation in a process to recover oil from the formation.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of pending U.S. Provisional Patent Application Ser. No. 61/927,276, filed Jan. 14, 2014, the entire reference is hereby incorporated within.

FIELD OF THE INVENTION

The present invention is directed to a composition for and a process of producing oil from an oil-bearing formation. In particular, the present invention is directed to a suspension for producing a foam composition and its use for producing oil from an oil-bearing formation.

BACKGROUND OF THE INVENTION

In the recovery of oil from subterranean formations, it is possible to recover only a portion of the oil in the formation using primary recovery methods utilizing the natural formation pressure to produce the oil. A portion of the oil that cannot be produced from a formation using primary recovery methods may be produced by flooding processes in which a displacing fluid such as water or a gas is injected through injection wells into the formation to mobilize and drive oil in the formation to wells from which the oil is produced.

Production of oil from an oil-bearing formation by such flooding processes may be limited by poor sweep efficiency of the displacing fluid through the formation and by an adverse mobility ratio between the displacing fluid and the oil in the formation, where the mobility of a fluid is the ratio of the relative permeability of the fluid through the formation to the fluid viscosity of that fluid. The sweep efficiency of a displacing fluid may be limited by permeability variations in the formation, where the displacing fluid preferentially sweeps through higher permeability zones in the formation and mobilizes the oil therein for production from the formation while little of the displacing fluid sweeps through lower permeability zones in the formation, leaving oil in place in the lower permeability zones. Further injection of more displacing fluid does not substantially improve recovery of oil from the lower permeability zones since the displacing fluid proceeds through the formation along established flow paths through higher permeability zones. An adverse mobility ratio between the displacing fluid and oil in the formation results in a less viscous displacing fluid such as water or a gas fingering or channeling through the more viscous oil in the formation as the displacing fluid proceeds through the formation from an injecting well to a producing well. The displacing fluid establishes a flow path through the channels or fingers, leaving the oil through which the displacing fluid has fingered in place in the formation. In a gas flood process where a gas is the displacing fluid, the gas may travel to the top of the formation and prematurely break through the oil to a producer well leaving much of the oil in the formation because the gas has comparatively much lower density than the oil.

Foams comprised of a gaseous phase dispersed in a continuous liquid phase containing a surfactant or other foaming agent have been utilized to improve the sweep efficiency of a gas for producing oil from an oil-bearing formation. Foam has an effective viscosity much higher than that of gas in a porous matrix, and can reduce viscous fingering and gravity override caused by the low viscosity and density of a gas relative to oil in the porous matrix of the formation. Furthermore, foam flows initially into high permeability zones in the formation and increases local resistance to flow in the high permeability zones, diverting further injected foam or fluids to zones of lower permeability, enabling mobilization and recovery of oil from the lower permeability zones of the formation. Foams containing an aqueous phase, a surfactant, and a gas phase, however, may be destabilized by contact with oil. Upon contact of the foam with oil, foam-forming surfactant may partition into the oil causing depletion in the aqueous phase and, therefore, from the gas-liquid interface of the foam; surfactants from the oil may be adsorbed by the foam lamellae to produce a less favorable state of foaming; oil may be adsorbed by the porous matrix of the formation altering the wettability of the formation and thereby making it more difficult for foam to be generated and regenerated in the formation; and the oil may spread spontaneously on foam lamellae and displace the foam stabilizing interface. As a result, forming and propagating foams containing an aqueous phase, a surfactant, and a gas phase through an oil-bearing formation to improve oil recovery may be impeded by contact with oil in the formation.

Foams that are stronger and more stable upon contact with oil, therefore, have been developed for use in oil recovery processes. Cross-linkable polymers have been included in a foam comprised of a liquid solvent, a surfactant, and a foaming gas, where the cross-linking polymers provide strength to the foam lamellae—stabilizing the lamellae when the foam is contacted with oil. Foams containing a fluorosurfactant have also been developed for use in recovering oil from an oil-bearing formation, where flurosurfactants are stable in the presence of oil.

Surface-modified nanoparticles have been included in a foam comprised of a surfactant, a solvent, and a gas to provide a stabilized foam. US Patent Appln. No. 2003/0220204 provides a process for oil recovery in which a foam containing surface-modified nanoparticles is used. The surface of the nanoparticles is modified by contacting the nanoparticles with a surface modifying agent that may be represented by the formula A-B, where the A group is capable of attaching to the surface of the particle and the B group is a compatibilizing group that modifies the solubility characteristics of the nanoparticles. Other ultrastable particle-stabilized foams have been developed that are useful in oil-recovery where colloidal particles of various chemical compositions are surface lyophobized through adsorption of short-chain amphiphilic molecules onto the particle surface.

Further compositions for forming strong, relatively oil-stable foams, foam compositions, and methods of using such compositions for oil recovery are desirable. In particular, compositions for forming particle-stabilized foams that are relatively oil-stable, wherein the particles utilized in the compositions for forming the foams are free of a surface modifying agent adsorbed or attached to the surface of the particles, foam compositions containing such particles, and processes of using such compositions for oil recovery are desirable.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a composition comprising water, a surfactant mixed with the water, and fly-ash particles suspended in the mixture of water and surfactant, wherein the fly-ash particles have a particle size distribution with an average particle size of less than 200 nm, and wherein the suspension of the fly-ash particles in the mixture of water and surfactant has an absolute zeta potential of from 10 mV to 40 mV. In an embodiment, the composition further comprises a gas dispersed within the suspension of fly-ash particles in the mixture of water and surfactant, wherein the composition is a foam.

In another aspect, the present invention is directed to a process for recovering oil from an oil-bearing formation, comprising: contacting a foam with oil in the oil-bearing formation, where the foam is comprised of a gas dispersed in a suspension comprised of fly-ash particles dispersed in a fluid comprised of water and a surfactant, wherein the fly-ash particles have a particle size distribution having an average particle size of at most 200 nm, and wherein the suspension has an absolute zeta potential of from 10 mV to 40 mV; and producing oil from the oil-bearing formation after contacting the foam with the oil in the oil-bearing formation.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawing figures depict one or more implementations in accordance with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.

FIG. 1 is a schematic diagram of an oil-production system and oil-bearing formation that may be utilized to effect a process of the present invention.

FIG. 2 is a schematic diagram of an oil-production system and oil-bearing formation illustrating the initial flow of a foam composition of the present invention in the formation in a process in accordance with the present invention.

FIG. 3 is a schematic diagram of an oil-production system and oil-bearing formation illustrating the uniform flow of a foam composition of the present invention in the formation in a process in accordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

In one aspect, the present invention is directed to a composition useful for formation of a foam for recovery of oil from an oil-bearing formation. In another aspect, the present invention is directed to a process for using the composition to recover oil from an oil-bearing formation.

The composition of the present invention is a suspension of fly-ash particles dispersed in a fluid that is a liquid mixture of water and a surfactant, where the fly-ash particles have a particle size distribution having an average particle size of less than 200 nm, and where the suspension has an absolute zeta potential of from 10 mV to 40 mV. A gas may be dispersed in the suspension to form a foam, and the composition of the present invention includes such a foam. The fly-ash particles stabilize a foam formed from the suspension, rendering the foam more stable than a foam comprised of the same materials absent the fly-ash particles. Although the present invention is not to be limited hereby, it is believed that the fly-ash particles stabilize the foam by collecting and agglomerating in nodes connecting liquid lamellae—the contact points between the liquid phase of adjoining bubbles in the foam—thereby inhibiting the drainage of water and/or surfactant from the lamellae. Furthermore, substantially less surfactant is required to form the foam than a foam formed in the absence of the fly-ash particles.

The fly-ash particles may be free of a surface modifying compound attached to the surface of the particles useful for dispersing the particles in an aqueous surfactant solution. The surface-modifying compound free fly-ash particles may be stably dispersed in the water and surfactant containing-fluid by selecting or adjusting the absolute zeta potential of the mixture of fly-ash particles and fluid within a range of from 10 mV to 40 mV. The absolute zeta potential of the suspension of fly-ash particles in the fluid may be adjusted by adjusting the pH. The pH of the liquid mixture may be adjusted, if necessary, to a pH of from 4.0 to 12 to enhance dispersion and suspension of the fly-ash particles in the liquid mixture to form the composition.

The composition of the present invention contains water in which a surfactant and fly-ash particles are mixed to form a suspension. The water utilized in the composition to form the suspension may be naturally occurring water selected from a source water selected from the group consisting of seawater, estuarine water, formation water, brackish water, aquifer water, river water, lake water, and mixtures thereof. The water utilized to form the suspension may also be treated water wherein a naturally occurring source water is treated to adjust the ionic content or suspended solids content of the source water, for example by removing suspended solids from the source water by ultrafiltration; or by removing ions from the source water using nanofiltration, reverse osmosis, or ion exchange; or by adding one or more water-soluble salts to a low salinity source water to increase the total dissolved solids (“TDS”) content of the water to inhibit formation damage when the suspension or foam is introduced into a fresh-water sensitive oil-bearing formation. The term “water” as used herein contemplates that the water may contain dissolved or suspended solids therein, and may contain other components present in naturally occurring source water. The water may have a TDS content selected to inhibit destabilization of the foam—where the stability of the foam relative to the TDS content of the water may be affected by the sensitivity of the surfactant utilized in the composition to salinity of the water. In an embodiment, the water may be selected to have, or may be treated to produce, a TDS content of 125,000 ppm or less, or of 100,000 ppm or less, or of 50,000 ppm or less.

In an embodiment, a naturally occurring water from a water source as described above may be treated to remove sulfate ions therefrom to inhibit souring of the formation into which the suspension of the composition or a foam produced therefrom is introduced. The naturally occurring water may be passed through one or more nanofiltration membranes to produce a treated water having a reduced sulfate ion content relative to the source water. The treated water may have a sulfate ion content of less than 200 ppm, or less than 100 ppm, or less than 50 ppm.

The composition of the present invention further comprises a surfactant, where the surfactant may be any surfactant effective to promote the formation of a foam upon being mixed with water and a gas under conditions of shear. The composition may comprise one or more surfactants. The surfactant may contain from 10 to 30 carbon atoms, or from 12 to 25 carbon atoms. The surfactant may be an anionic surfactant, a cationic surfactant, a zwitterionic surfactant, or a non-ionic surfactant. Cationic surfactants that may be included in the composition include pH dependent primary, secondary, or tertiary amines and quaternary ammonium cations. Zwitterionic surfactants that may be included in the composition include surfactants with a pH dependent primary, secondary, or tertiary amine or quaternary ammonium cation head and a sulfonate, sultaine, or betaine anionic head. Non-ionic surfactants that may be included in the composition include polyether alcohols and glycols. The composition of the present invention may be free of fluorosurfactant compounds.

In a preferred embodiment, the composition comprises an anionic surfactant. The anionic surfactant may be a sulfonate-containing compound, a sulfate-containing compound, a carboxylate compound, a phosphate compound, or a blend thereof. The anionic surfactant may be an alpha olefin sulfonate compound, an internal olefin sulfonate compound, a branched alkyl benzene sulfonate compound, a propylene oxide sulfate compound, an ethylene oxide sulfate compound, a propylene oxide-ethylene oxide sulfate compound, or a blend thereof. The anionic surfactant may contain from 12 to 28 carbon atoms, or from 12 to 20 carbon atoms. Preferably, the surfactant of the composition is an internal olefin sulfonate compound or an alpha olefin sulfonate compound containing from 12 to 20 carbon atoms or a blend thereof.

The surfactant is mixed with the water to form a fluid in which the fly-ash particles are dispersed and suspended. The surfactant is present in the composition in an amount effective to promote the formation of a stable foam upon mixing with a gas. The composition of the present invention may contain less surfactant than conventional aqueous surfactant compositions utilized to produce foams for enhanced oil recovery due to the presence of the stabilizing fly-ash particles in the composition. The surfactant may comprise from 0.01 wt. % to 0.5 wt. % of the composition, or from 0.05 wt. % to 0.3 wt. % of the composition whereas conventional aqueous surfactant compositions utilized to produce foams may typically contain from 0.5 wt. % to 5 wt. % of surfactant. The selection of concentration of the surfactant will depend on the salinity of the formation brine and the critical micelle concentration of the selected surfactant, as may be determined in accordance with conventional methods of preparing foaming compositions.

The composition of the present invention further comprises fly-ash particles. The fly-ash particles have a particle size distribution having an average particle size of at most 200 nanometers (nm). The fly-ash particles preferably have a particle size distribution having an average particle size of from 100 nm to 200 nm The fly-ash particles may be comprised of silica, and preferably are substantially comprised of silica. The fly-ash particles may be free of a surface modifying compound attached to the surface of the particles.

The fly-ash particles may be produced from a commercially available fly-ash feedstream having a particle size distribution with an average particle size of greater than 200 nm The fly-ash feedsteam may be fly-ash produced as a waste byproduct in a power plant. The fly-ash feedstream may be ground to reduce the particle size of the fly-ash in the feedstream, then the fly-ash particles having an average particle size of at most 200 nm may be separated from the ground fly-ash feedstream. The fly-ash particles having an average particle size of at most 200 nm may be separated from the ground fly-ash feedstream by suspending the ground fly-ash feedstream in water and treating the suspension with ultrasound to separate particles having the selected particle size according to conventional ultrasound particle separation methods. The ultrasound power should be in a range that causes cavitation in the fly-ash feedstream/water suspension, preferably in a pressure vessel. The resulting aqueous suspension of fly-ash particles having an average particle size of at most 200 nm may be dried to produce dry fly-ash particles for mixing with water and surfactant to produce a suspension, or may be directly mixed with surfactant, and, if necessary additional water, to produce the suspension of the composition.

The fly-ash particles are present in the composition of the present invention in an amount effective to stabilize a foam produced by mixing the suspension of the composition with a gas, or, when the composition is a foam comprised of the suspension and a gas, an amount effective to stabilize the foam. The fly-ash particles may be present in the suspension comprised of water, surfactant, and the fly-ash particles in an amount of from 0.1 mg/ml to 3 mg/ml, and preferably in an amount of from 0.5 mg/ml to 2 mg/ml.

The water, surfactant, and fly-ash particles are mixed to form the suspension of the composition of the present invention. The water, surfactant, and fly-ash particles may be mixed by conventional means for mixing liquids and a fine particulate solid, for example in a mechanically stirred tank. The suspension may be prepared by mixing the water, surfactant, and fly-ash particles in substantially any order and manner. The water, surfactant, and fly-ash particles may all be mixed together at one time. Alternatively, the fly-ash particles may be dispersed in water as a result of separating the fly-ash particles from a fly-ash feedstream, and a surfactant may be added to the aqueous dispersion of fly-ash particles. Alternatively, the water and surfactant may be mixed together followed by addition of the fly-ash particles to the mixture to form the suspension.

The suspension has an absolute zeta potential of from 10 mV to 40 mV, wherein the absolute zeta potential is a measurement of the charge on the surface of the particles in the suspension which is an indicator of the stability of the dispersion of the fly-ash particles therein. The suspension of the composition more preferably has an absolute zeta potential of from 25 mV to 35 mV. The absolute zeta potential of the suspension may be measured in accordance with conventional zeta potential measurement methods and techniques.

If the suspension has an absolute zeta potential of less than 10 mV or greater than 40 mV, the absolute zeta potential of the suspension may be adjusted to be within a range of from 10 mV to 40 mV by adding an inorganic acid or an inorganic base to the suspension. The composition of the present invention, therefore, may also be comprised of an inorganic acid or an inorganic base, or ionic components thereof. The inorganic acid may be selected from the group consisting of hydrochloric acid, nitric acid, and sulfuric acid, and is preferably hydrochloric acid. The inorganic base may be selected from sodium hydroxide, potassium hydroxide, and ammonium hydroxide, and is preferably sodium hydroxide.

The composition suspension may have a pH of from 4.0 to 12.0, and more preferably from 4.0 to 8.5. If the composition suspension has a pH of less than 4.0 or greater than 12.0 (or 8.5), the pH of the suspension may be adjusted to a range of from 4.0 to 12.0 (or 8.5) by adding an inorganic acid to the suspension if the pH is above 12.0 (or 8.5) or by adding an inorganic base to the suspension if the pH of the suspension is below 4.0, where the inorganic acids and inorganic bases used to adjust the pH of the suspension may be those described above.

The composition of the invention may also comprise a gas, wherein the composition is a foam in which the gas forms a discontinuous phase within a continuous phase of the suspension described above. The gas may be any foaming gas which is substantially non-reactive with the components of the suspension, and preferably which is substantially non-reactive with a crude oil. Foaming gases that may be utilized as the gas in the composition of the present invention may be selected from the group consisting of nitrogen; carbon dioxide; air; a hydrocarbon-containing gas including, but not limited to, methane, ethane, propane, butane, natural gas, and mixtures thereof; flue gas; and mixtures thereof. Preferably the gas is either carbon dioxide or nitrogen. As described in further detail below with respect to the process of the present invention, the foam may be formed by mechanical shear and mixing of the gas and the suspension.

The composition of the present invention, when it is a foam, may have a foam quality effective to provide the foam with significant viscosity relative to the gas used to form the foam. Foam quality is defined herein as the volume of gas within a foam divided by the total volume of the foam*100%. In foams having a foam quality of 50% or greater, bubbles within the foam touch each other thereby allowing less freedom of bubble movement within the foam and increasing the viscosity of the foam. Increasing foam quality generally increases the viscosity of the foam. The composition of the present invention, when it is a foam, comprises a gas and may have a foam quality of at least 50%, and preferably has a foam quality of from 50% to 90%.

The present invention is also directed to a process for recovering oil from an oil-bearing formation utilizing a foam of the composition described above or formed from the suspension of the composition described above. As described above, the foam is relatively stable due to the fly-ash particles, enabling the foam to drive further into a formation from an injection well relative to a comparable foam that does not contain the fly-ash particles. Oil recovery from the formation may be improved by utilization of the fly-ash particle stabilized foam.

As used in the following description of the process of the present invention, the “foam” refers to a foam of the composition as described above, and the “suspension” refers to a suspension of the composition described above. The suspension used in the process of the present invention may be any suspension as described above, for example, the suspension may or may not contain an inorganic acid or inorganic base or ionic components thereof, and may or may not have been pH adjusted; or the suspension may or may not include an anionic surfactant etc. Similarly, the foam used in the process of the present invention may be any foam as described above.

In the process of the present invention, the foam is contacted with oil in an oil-bearing formation, and oil is produced from the oil-bearing formation after contacting the foam with the oil in the oil-bearing formation. The oil-bearing formation may be comprised of a porous matrix material, oil, and connate water. The oil-bearing formation comprises oil that may be separated and produced from the formation after contact of the foam with oil in the formation.

The porous matrix material of the formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone and/or a carbonate selected from dolomite, limestone, and mixtures thereof—where the limestone may be microcrystalline or crystalline limestone. The formation may have a permeability of from 0.00001 to 15 Darcy's, or from 0.001 to 1 Darcy.

The oil-bearing formation may be a subterranean formation. The subterranean formation may be comprised of one or more porous matrix materials described above, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6,000 meters, or from 100 meters to 4,000 meters, or from 200 meters to 2,000 meters under the earth's surface. The subterranean formation may be a subsea formation.

Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation.

The oil-bearing formation may also be comprised of water, which may be located in pores within the porous matrix material. The water in the formation may be connate water, water from a secondary or tertiary oil recovery process water-flood, or a mixture thereof. The water in the oil-bearing formation may be positioned to immobilize oil within the pores. Contact of the foam with the oil in the formation may mobilize at least a portion of the oil in the formation for production and recovery from the formation by freeing at least a portion of the oil from pores within the formation.

Referring now to FIG. 1, the foam may be generated for contact with oil in the oil-bearing formation 101 by introducing the gas and the suspension into the formation through an injection well 103. The suspension may be provided to the injection well 103 for introduction into the formation from a suspension storage facility 105, and the gas may be provided to the injection well for introduction into the formation from a gas storage facility 107. The gas and the suspension may be introduced into the formation 101 by injection through the injection well 103, for example, through perforations in the injection well located in the oil-bearing portion of the formation.

The gas and the suspension are introduced into the formation 101 in an amount and in proximity relative to each other to form the foam 111 in the formation upon being injected into the formation. In one embodiment of the process of the present invention, at least a portion of the gas and at least a portion of the suspension are co-injected into the formation 101 to form the foam in the formation. The gas and the suspension may be mixed at the injection wellhead of the injection well 103 and co-injected into the formation 101 as a mixture, where shear forces exerted on the mixture upon injection of the mixture into the formation and pressure differentials between the injection pressure and the formation pressure generate the foam 111 from the mixture within the formation. Alternatively, the gas and the suspension may be co-injected into the formation 101 though separate injection strings in the injection well 103, where the separate injection strings may inject the gas and the suspension through the same perforations or through adjacent perforations in the injection well such that the gas and the suspension are mixed together in the formation adjacent the injection well under conditions effective to produce a foam 111.

When the suspension and the gas are co-injected into the formation 101 to form the foam 111, the rate of injection of the suspension and the gas may be controlled to produce a foam within the formation having a selected foam quality. The suspension and the gas may be injected into the formation 101 at a fixed flowrate ratio to produce the foam having a selected foam quality. The foam quality, f_(g), is defined as f_(g)=q_(g)/(q_(g)+q)*100% where q_(g) is the flowrate of the gas into the formation and q_(s) is the flowrate of the suspension into the formation. Preferably the suspension and the gas are injected at relative flowrates effective to produce a foam having a foam qualtity of at least 40%, and preferably from 45% to 85%, in the formation. The velocity of the injection of the suspension and/or the gas into the formation can range from 1 ft/day to 500 ft/day.

The combined co-injected suspension and gas may be injected in an amount effective to sweep up to 3 pore volumes (PV) of the formation with the foam 111 formed from the suspension and the gas, where the term “pore volume” refers to the volume of the formation that may be swept by the foam between the injection well 103 and a production well 109 from which oil is produced. The combined co-injected suspension and gas may be injected in an amount effective to sweep from 0.6 PV to 2 PV of the formation with the resulting foam, and more preferably in an amount effective to sweep from 0.9 PV to 1.5 PV of the formation.

In another embodiment of the process of the present invention, the suspension and the gas may be introduced into the formation 101 by alternately injecting slugs of the suspension and the gas into the formation through an injection well 103. A slug of the suspension may be injected into the formation first through the injection well. A slug of the gas then may be injected into the formation to contact the slug of suspension previously injected into the formation to form a foam 111 with the previously injected suspension in the formation. Additional slugs of the suspension and the gas then may be alternately injected into the formation to form further foam. The slugs of the suspension and the gas should be injected into the formation proximate to the preceding slug of suspension or gas so that the suspension and gas contact each other and form a foam in the formation.

The alternate slugs of the suspension and the gas may be introduced into the formation in an amount effective to form a foam 111 utilizing a substantial portion of the injected suspension and gas slugs. In an embodiment of the process of the present invention, each slug of the suspension and each slug of the gas may be from 0.03 PV to 0.2 PV of the volume of the formation that may be swept by the foam between the injection well 103 and the production well 109. Preferably each slug of the suspension and each slug of the gas may be from 0.05 PV to 0.15 PV of the volume of the formation that may be swept by the foam between the injection well and the production well. The combined slugs of suspension and gas introduced into the formation may be injected into the formation in an amount effective to sweep from 0.6 PV to 2 PV of the formation with the resulting foam, and more preferably in an amount effective to sweep from 0.9 PV to 1.5 PV of the formation.

The suspension and the gas, whether co-injected or injected in separate slugs, may be introduced into the formation 101 at a pressure effective to promote formation of the foam 111 upon contact of the gas and the suspension in the formation. The pressure differential between the injection pressure of the suspension and the gas and the formation pressure may be related to the production of the foam and the relative strength of the foam, where stronger foams may be produced at greater pressure differentials between the injection pressure and the formation pressure. In an embodiment of the process, the suspension and/or the gas may be injected into the formation at a pressure of at least 5% greater than the formation pressure up to the fracture pressure of the formation, or of at least 10% greater than the formation pressure up to the fracture pressure of the formation, or of at least 20% greater than the pressure of the formation up to the fracture pressure of the formation.

The suspension and/or the gas may also be injected into the formation 101 at a pressure greater than the fracture pressure of the formation. Injection of the suspension and/or the gas into the formation at pressures above the fracture pressure of the formation may create fractures in the formation in which the foam may form due to the permeability of the fractures within the formation. Such fractures may permit access to previously low permeability zones within the formation since the foam may reduce the mobility of further foam or gas through the fractures and redirect the foam or gas through adjacent low permeability zones in the formation.

The foam 111 is contacted with oil in the formation 101 upon introduction of the foam into the oil-bearing formation. The foam 111 may displace oil in the formation 101—mobilizing and driving oil in the formation to one or more production wells 109 for production of oil from the formation. The foam 111 may mobilize oil for production from the formation 101 by reducing the capillary forces holding oil in pores by reduction of interfacial tension due to the surfactant in the foam, by physically displacing the oil from within pores in the porous matrix of the formation, by dissolution, by viscosity reduction, and/or by swelling the oil.

The foam may drive the mobilized oil through the formation 101 for production from a production well 109 as more foam is introduced into the formation. As shown in FIG. 2, the foam and mobilized oil may initially flow from an injection well 103 towards a production well 109 through the formation 101 in a high permeability zone 201 more readily than in a low permeability zone 203. The foam in the high permeability zone 203 increases resistance of flow of further foam through the high permeability zone due to the apparent viscosity of the foam in the high permeability zone, redirecting a portion of foam injected into the formation into the low permeability zone 203. As shown in FIG. 3, the foam and mobilized oil may then flow through the formation 101 from the injection well 103 to the production well 109 through both the high permeability zone 201 and the low permeability zone 203 in a relatively uniform front—enhancing the amount of oil produced from the formation by mobilizing and driving oil in the low permeability zone 203 as well as oil in the high permeability zone for production from the production well 109. Furthermore, the mobility ratio of the foam to oil in the formation may promote uniform flow of the foam and mobilized oil through the formation and may inhibit fingering of the foam through the oil.

Referring back to FIG. 1, oil is produced from the formation 101 after contacting the foam 111 with the oil in the formation. Oil is mobilized and driven through the formation 101 by contact with the foam 111 as shown by arrows 113, 115, 117, and 119. Oil mobilized and driven through the formation by contact with the foam may be produced from the formation through the production well 109. The oil produced from the formation may be produced by any conventional means for producing oil from a formation known to those skilled in the art of oil recovery and production. For example, the oil may be produced by providing artificial lift to recover the oil from the formation, for example, by pumping the oil from the formation or by gas lift.

The oil produced from the formation 101 may be treated and stored. The oil produced from the formation 101 may be treated to separate oil from water and/or gases that may be co-produced from the formation with the oil. The separation of oil from co-produced water and/or gases may be effected by conventional separation processes known to those skilled in the art of oil production. The produced and separated oil may be stored in an oil storage facility 121.

The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. While systems and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from a to b,” or, equivalently, “from a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value “about” the specified lower limit and/or the specified upper limit Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. 

What is claimed:
 1. A composition comprising, water; a surfactant mixed with the water; and fly-ash particles suspended in the mixture of water and surfactant, wherein the fly-ash particles have a particle size distribution with an average particle size of less than 200 nm, and wherein the suspension of fly-ash particles in the mixture of water and surfactant has an absolute zeta potential of from 10 mV to 40 mV.
 2. The composition of claim 1 wherein the suspension has a pH of from 4.0 to 12.0.
 3. The composition of claim 1 further comprising an inorganic acid or an inorganic base mixed in the suspension.
 4. The composition of claim 3 wherein the inorganic acid is hydrochloric acid.
 5. The composition of claim 3 wherein the inorganic base is sodium hydroxide.
 6. The composition of claim 1 wherein the surfactant is an anionic surfactant.
 7. The composition of claim 6 wherein the anionic surfactant is an alpha-olefin sulfonate.
 8. The composition of claim 1 wherein the surfactant is a cationic surfactant, an amphoteric surfactant, or a non-ionic surfactant.
 9. The composition of claim 1 wherein the fly-ash particles are free of a surface modifying compound attached to the surface of the fly-ash particles.
 10. The composition of claim 1 wherein the fly-ash particles are comprised of silica.
 11. The composition of claim 1 wherein the suspension comprises from 0.01 wt. % to 0.5 wt. % of the surfactant and from 0.1 mg/ml to 3 mg/ml of the fly-ash particles.
 12. The composition of claim 1 further comprising a gas dispersed within the suspension, wherein the composition is a foam.
 13. The composition of claim 1 wherein the fly-ash particles have a particle size distribution with an average particle size of from 100 nm to 200 nm.
 14. The composition of claim 1 wherein the suspension has a zeta potential of from 25 mV to 35 mV
 15. A process for recovering oil from an oil-bearing formation comprising: contacting a foam with oil in the oil-bearing formation, where the foam is comprised of a gas dispersed in a suspension comprised of fly-ash particles dispersed in a fluid comprised of water and a surfactant, wherein the fly-ash particles have a particle size distribution having an average particle size of at most 200 nm, and wherein the suspension has an absolute zeta potential of from 10 mV to 40 mV; and producing oil from the oil-bearing formation after contacting the foam with the oil in the oil-bearing formation.
 16. The process of claim 15, further comprising displacing oil in the formation with the foam.
 17. The process of claim 15 wherein the surfactant is an anionic surfactant.
 18. The process of claim 15 wherein the fly-ash particles are free of a surface modifying compound attached to the surface of the fly-ash particles.
 19. The process of claim 15 wherein the fly-ash particles are comprised of silica.
 20. The process of claims 15, wherein the foam further comprises an inorganic acid or an inorganic base or ionic components thereof.
 21. The process of claim 15, wherein the fly-ash particles have a particle size distribution having an average particle size of from 100 nm to 200 nm.
 22. The process of claim 15 wherein the suspension has a pH of from 4.0 to 8.5.
 23. The process of claim 22 further comprising the step of adding an inorganic acid or an inorganic base to the suspension to adjust the pH of the suspension to a pH of from 4.0 to 12.0.
 24. The process of claim 15 further comprising adding an inorganic acid or an inorganic base to the suspension to adjust the absolute zeta potential of the suspension to 10 mV to 40 mV.
 25. The process of claim 15 wherein the gas is carbon dioxide, nitrogen, or a mixture thereof.
 26. The process of claim 15 further comprising the steps of: introducing the suspension into the oil-bearing formation; introducing the gas into the formation and contacting the gas with the suspension in the formation to form the foam in the formation.
 27. The process of claim 26 further comprising the step of co-injecting at least a portion of the suspension and at least a portion of the gas into the formation to introduce the suspension and the gas into the formation.
 28. The process of claim 26 further comprising the steps of: injecting at least a portion of the suspension into the formation to introduce the suspension into the formation; injecting at least a portion of the gas into the formation after injecting at least a portion of the suspension into the formation to introduce the gas into the formation.
 29. The process of claim 28 further comprising the steps of alternately injecting at least two portions of the suspension and at least two portions of the gas into the formation.
 30. The process of claim 15, further comprising: separating the fly-ash particles from a fly-ash feedstream having a particle size distribution with an average particle size of greater than 200 nm; dispersing the separated fly-ash particles in the fluid comprised of water and surfactant to form the suspension. 